Method for Quantifying Reservoir Connectivity Using Fluid Travel Times

1. A method for producing hydrocarbons comprising: constructing a plurality of fluid travel time models from a reservoir model; calculating reservoir connectivity measures from the plurality of fluid travel time models; analyzing the reservoir connectivity measures to determine a location for at least one well; drilling the at least one well based on the analysis; and producing hydrocarbons from the drilled at least one well.

2. The method of claim 1 wherein constructing the plurality of fluid travel time models comprises creating the plurality of fluid travel time models via a graph theory method.

3. The method of claim 1 wherein constructing the plurality of fluid travel time models comprises: nondimensionalizing the reservoir model; selecting a flow network model; assigning volume properties to a plurality of nodes in the flow network model; assigning flow properties to a plurality of connections in the flow network model; selecting at least one of the nodes to represent at least one well; calculate a value for each of the nodes to the selected at least one of the nodes; and assigning fluid travel times to each of the plurality of nodes.

4. The method of claim 3 wherein the flow network model comprises nodes and connections.

5. The method of claim 4 wherein the flow network model comprises an eight-neighbor model to reduce orientation errors.

6. The method of claim 3 wherein the volume properties comprise total volume, pore volume, hydrocarbon pore volume, and any combination thereof.

7. The method of claim 3 wherein the flow properties comprise permeability, porosity, fluid density, fluid viscosity, fluid travel time and any combination thereof.

8. The method of claim 1 wherein constructing the plurality of fluid travel time models comprises creating the plurality of fluid travel time models via a front propagation method.

9. The method of claim 1 wherein constructing the plurality of fluid travel time models comprises: nondimensionalizing the reservoir model; defining a plurality of nodes in a node model from the nondimensionalized reservoir model; assigning volume properties and travel velocities to each of the plurality of nodes; selecting at least one of the plurality of nodes to represent a well; and calculating fluid travel times for each of the plurality of nodes.

10. The method of claim 9 wherein the volume properties comprise total volume, pore volume, hydrocarbon pore volume, and any combination thereof.

11. The method of claim 1 wherein calculating the reservoir connectivity measures from the plurality of fluid travel time models comprises calculating reservoir connectivity measures for a plurality of dimensions.

12. The method of claim 11 wherein the plurality of dimensions comprise at least two of a time dimension, size dimension, orientation dimension and a space dimension.

13. The method of claim 11 wherein calculating the reservoir connectivity measures from the plurality of fluid travel time models comprises: calculating reservoir connectivity measures for primary depletion; calculating reservoir connectivity measures for secondary and tertiary recoveries; and calculating local connectivity measures.

14. The method of claim 13 wherein calculating the reservoir connectivity measures for primary depletion comprises: calculating producible pore volume and producible time; and calculating producible volume aspect ratio.

15. The method of claim 13 wherein calculating reservoir connectivity measures for secondary and tertiary recoveries comprises: calculating interconnected pore volume plateau length; and calculating interconnected pore volume decline coefficient.

16. The method of claim 13 wherein calculating local connectivity measures comprise: calculating interconnected pore volume plateau length; and calculating interconnected pore volume decline coefficient.

17. The method of claim 1 further comprising creating connectivity regions from the reservoir connectivity measures to determine the location for the at least one well.

18. The method of claim 1 further comprising creating connectivity maps to guide optimization of the location of the at least one well.

19. The method of claim 1 further comprising estimating fluid travel times without flow simulation to create the plurality of fluid travel time models.

20. A method for evaluating a reservoir model comprising: obtaining a reservoir model; nondimensionalizing the reservoir model; constructing a plurality of fluid travel time models from the nondimensionalized reservoir model; calculating reservoir connectivity measures from the plurality of fluid travel time models; and analyzing the reservoir connectivity measures to determine the location of at least one well for a reservoir.

21. The method of claim 20 wherein constructing the plurality of fluid travel time models comprises creating the plurality of fluid travel time models via a graph theory method.

22. The method of claim 20 wherein constructing the plurality of fluid travel time models comprises: selecting a flow network model; assigning volume properties to a plurality of nodes in the flow network model; assigning flow properties to a plurality of connections in the flow network model; selecting at least one of the nodes to represent at least one well; calculate a value for each of the nodes to the selected at least one of the nodes; and assigning fluid travel times to each of the plurality of nodes.

23. The method of claim 22 wherein the volume properties comprise at least one of total volume, pore volume, hydrocarbon pore volume, and any combination thereof.

24. The method of claim 22 wherein the flow properties comprise at least one of permeability, porosity, fluid density, fluid viscosity, fluid travel time and any combination thereof.

25. The method of claim 20 wherein constructing the plurality of fluid travel time models comprises creating the plurality of fluid travel time models via a front propagation method.

26. The method of claim 20 wherein constructing the plurality of fluid travel time models comprises: defining a plurality of nodes in a node model from the nondimensionalized reservoir model; assigning volume properties and travel velocities to each of the plurality of nodes; selecting at least one of the plurality of nodes to represent a well; and calculating fluid travel times for each of the plurality of nodes.

27. The method of claim 26 wherein the volume properties comprise at least one of total volume, pore volume, hydrocarbon pore volume, and any combination thereof.

28. The method of claim 20 wherein calculating the reservoir connectivity measures from the plurality of fluid travel time models comprises calculating reservoir connectivity measures for a plurality of dimensions.

29. The method of claim 28 wherein the plurality of dimensions comprise at least two of a time dimension, size dimension, orientation dimension and a space dimension.

30. The method of claim 28 wherein calculating the reservoir connectivity measures from the plurality of fluid travel time models comprises: calculating reservoir connectivity measures for primary depletion; calculating reservoir connectivity measures for secondary and tertiary recoveries; and calculating local connectivity measures.

31. The method of claim 30 wherein calculating the reservoir connectivity measures for primary depletion comprises: calculating producible pore volume and producible time; and calculating producible volume aspect ratio.

32. The method of claim 30 wherein calculating reservoir connectivity measures for secondary and tertiary recoveries comprises: calculating interconnected pore volume plateau length; and calculating interconnected pore volume decline coefficient.

33. The method of claim 30 wherein calculating local connectivity measures reservoir comprise: calculating interconnected pore volume plateau length; and calculating interconnected pore volume decline coefficient.

34. The method of claim 20 further comprising creating connectivity regions from the reservoir connectivity measures to determine the location for the at least one well.

35. The method of claim 20 further comprising creating connectivity maps to guide optimization of the location of the at least one well.

36. The method of claim 20 further comprising estimating fluid travel times without flow simulation to create the plurality of fluid travel time models.

37. A system associated with the production of hydrocarbons comprising: a processor; memory coupled to the processor; an application stored in the memory and configured to: construct a plurality of fluid travel time models from a reservoir model; calculate reservoir connectivity measures from the plurality of fluid travel time models; and a monitor coupled to the processor and configured to present the reservoir connectivity measures.

38. The system of claim 37 wherein the application is configured to: nondimensionalize the reservoir model; select a flow network model; assign volume properties to a plurality of nodes in the flow network model; assign flow properties to a plurality of connections in the flow network model; select at least one of the nodes to represent at least one well; calculate a value for each of the nodes to the selected at least one of the nodes; and assign fluid travel times to each of the plurality of nodes.

39. The system of claim 38 wherein the volume properties comprise total volume, pore volume, hydrocarbon pore volume, and any combination thereof.

40. The system of claim 38 wherein the flow properties comprise permeability, porosity, fluid density, fluid viscosity, fluid travel time and any combination thereof.

41. The system of claim 37 wherein the application is configured to: nondimensionalize the reservoir model; define a plurality of nodes in a node model from the nondimensionalized reservoir model; assign volume properties and travel velocities to each of the plurality of nodes; select at least one of the plurality of nodes to represent a well; and calculate fluid travel times for each of the plurality of nodes.

42. The system of claim 41 wherein the volume properties comprise total volume, pore volume, hydrocarbon pore volume, and any combination thereof.

43. The system of claim 38 wherein the application is configured to calculate the reservoir connectivity measures from the plurality of fluid travel time models for a plurality of dimensions.

44. The system of claim 43 wherein the plurality of dimensions comprise at least two of a time dimension, size dimension, orientation dimension and a space dimension.

45. The system of claim 43 wherein the application is configured to: calculate reservoir connectivity measures for primary depletion; calculate reservoir connectivity measures for secondary and tertiary recoveries; and calculate local connectivity measures.

46. The system of claim 45 wherein the application is configured to: calculate producible pore volume and producible time; and calculate producible volume aspect ratio.

47. The system of claim 45 wherein the application is configured to: calculate interconnected pore volume plateau length; and calculate interconnected pore volume decline coefficient.

48. The system of claim 45 wherein the application is configured to: calculate interconnected pore volume plateau length; and calculate interconnected pore volume decline coefficient.

49. The system of claim 37 wherein the application is configured to create connectivity regions from the reservoir connectivity measures to determine the location for the at least one well.

50. The system of claim 37 wherein the application is configured to create connectivity maps to guide optimization of a location for wells.

51. The system of claim 37 wherein the application is configured to estimate fluid travel times without flow simulation that are used to create the plurality of fluid travel time models.

52. A method for evaluating a reservoir model comprising: constructing a plurality of fluid travel time models from a reservoir model; calculating reservoir connectivity measures from the plurality of fluid travel time models; and analyzing the reservoir connectivity measures to determine a location for at least one well.

53. The method of claim 52 wherein constructing the plurality of fluid travel time models comprises creating the plurality of fluid travel time models via a graph theory method.

54. The method of claim 52 wherein constructing the plurality of fluid travel time models comprises: nondimensionalizing the reservoir model; selecting a flow network model; assigning volume properties to a plurality of nodes in the flow network model; assigning flow properties to a plurality of connections in the flow network model; selecting at least one of the nodes to represent at least one well; calculate a value for each of the nodes to the selected at least one of the nodes; and assigning fluid travel times to each of the plurality of nodes.

55. The method of claim 54 wherein the flow network model comprises nodes and connections.

56. The method of claim 54 wherein the flow network model comprises an eight-neighbor model to reduce orientation errors.

57. The method of claim 54 wherein the volume properties comprise total volume, pore volume, hydrocarbon pore volume, and any combination thereof.

58. The method of claim 54 wherein the flow properties comprise permeability, porosity, fluid density, fluid viscosity, fluid travel time and any combination thereof.

59. The method of claim 52 wherein constructing the plurality of fluid travel time models comprises creating the plurality of fluid travel time models via a front propagation method.

60. The method of claim 52 wherein constructing the plurality of fluid travel time models comprises: nondimensionalizing the reservoir model; defining a plurality of nodes in a node model from the nondimensionalized reservoir model; assigning volume properties and travel velocities to each of the plurality of nodes; selecting at least one of the plurality of nodes to represent a well; and calculating fluid travel times for each of the plurality of nodes.

61. The method of claim 60 wherein the volume properties comprise total volume, pore volume, hydrocarbon pore volume, and any combination thereof.

62. The method of claim 52 wherein calculating the reservoir connectivity measures from the plurality of fluid travel time models comprises calculating reservoir connectivity measures for a plurality of dimensions.

63. The method of claim 62 wherein the plurality of dimensions comprise at least two of a time dimension, size dimension, orientation dimension and a space dimension.

64. The method of claim 62 wherein calculating the reservoir connectivity measures from the plurality of fluid travel time models comprises: calculating reservoir connectivity measures for primary depletion; calculating reservoir connectivity measures for secondary and tertiary recoveries; and calculating local connectivity measures.

65. The method of claim 64 wherein calculating the reservoir connectivity measures for primary depletion comprises: calculating producible pore volume and producible time; and calculating producible volume aspect ratio.

66. The method of claim 64 wherein calculating reservoir connectivity measures for secondary and tertiary recoveries comprises: calculating interconnected pore volume plateau length; and calculating interconnected pore volume decline coefficient.

67. The method of claim 64 wherein calculating local connectivity measures reservoir comprise: calculating interconnected pore volume plateau length; and calculating interconnected pore volume decline coefficient.

68. The method of claim 52 further comprising creating connectivity regions from the reservoir connectivity measures to determine the location for the at least one well.

69. The method of claim 52 further comprising creating connectivity maps to guide optimization of the location of the at least one well.

70. The method of claim 52 further comprising estimating fluid travel times without flow simulation to create the plurality of fluid travel time models.